This disclosure relates to land seismic exploration for oil and gas, and seismic imaging of near-surface and subsurface layers. Conventional seismic methods for exploring subterranean strata beneath the Earth's surface involve generating a seismic wave and measuring the response. The seismic wave may be simple or complex and may be generated at various locations. The response is detected by a series of receivers. Various methods, techniques, and equipment for generating a seismic wave and recording the response are known in the industry and to one having ordinary skill in the art.
The near-surface earth formation usually is composed of a soil column with low-velocity clastics, such as clay, silt and sand with fine- to coarse-grained texture. The near-surface earth formation can be layered or severely heterogeneous with vertical and lateral velocity variations. Moreover, the thickness of the near-surface formation often varies within the seismic survey area. The term “near-surface earth formation” has an understood meaning in the field of land seismic exploration for oil and gas and would be understood by one having ordinary skill in the art.
In land seismic exploration for oil and gas, the near-surface earth formation distorts the seismic image of the subsurface earth formation, or that portion of the earth formation directly below the near-surface earth formation. As such, accurate mapping of the geometry of hydrocarbon reservoirs requires correcting for the deleterious effect of the near-surface formation on the imaged geometry of the subsurface formation layers.
Correction of near-surface distortions usually is performed by the application of vertical (static) time shifts to the recorded data traces. Statics corrections, however, require an accurate model of the near-surface formation represented by a velocity field associated with the near-surface soil column.
In the seismic industry, there are several classes of methods to estimate a model for the near-surface formation, including downhole seismic measurements, shallow seismic surveys, traveltime tomography inversion, and waveform tomography inversion.
A first method for estimating a model for the near-surface formation includes downhole seismic measurements. Downhole seismic measurements are time consuming and prohibitively costly, and suffer from adverse borehole conditions. Additionally, the downhole seismic measurement method provides the velocity information for the near-surface only at the survey points within the project or analysis area.
A second method for estimating a model for the near-surface formation includes shallow seismic surveys. Shallow seismic surveys also are time consuming and, similar to the downhole seismic measurement method, provide the velocity information for the near-surface only at the survey points.
A third category of method for estimating a model for the near-surface formation includes tomographic inversion. Tomographic inversion of first-arrival times requires picking or choosing the first-arrival times from recorded seismic data. This is an extremely tedious and time-consuming effort, prone to serious picking errors, especially with data acquired by vibroseis source. The additional time required for the quality control of the first-break picks and numerically intensive computation required for the tomographic inversion make this method rather expensive for large 3-D land seismic projects. Tomographic inversion of early-arrival waveforms requires accurate estimate of the source waveform, and involves extremely intensive computation which can take several weeks, if not months, for a 3-D land seismic project of moderate size (for example, a few hundred square kilometers). Additionally, for this method to yield acceptable results, the wavefield modeling required for the inversion would have to be performed using the elastic wave equation. Finally, traveltime and waveform tomography methods both suffer from the velocity-depth ambiguity that is transcribed to non-uniqueness of the estimated model.
The embodiments disclosed herein overcome the aforementioned limitations of the prior art.